1. Field of the Disclosure
The present subject matter is generally directed to drilling operations, and in particular, to systems, apparatuses, and methods that may be used for recovering high density solids particles such as barite from drilling fluid.
2. Description of the Related Art
During a typical well drilling operation, such as when an oil and gas well is drilled into the earth, a drilling mud circulation and recovery system is generally used to circulate drilling fluid, i.e., drilling mud, into and out of a wellbore. The drilling mud provides many functions and serves many useful purposes during the drilling operation, such as, for example, removing drill cuttings from the well, controlling formation pressures and wellbore stability during drilling, sealing permeable formations, transmitting hydraulic energy to the drilling tools and bit, and cooling, lubricating, and supporting the drill bit and drill assembly during the drilling operations.
In order to control formation pressures and wellbore stability during drilling operations, the drilling mud must have a great enough density so that the weight of the column of fluid at any point in the wellbore is sufficient to prevent the local geological forces in the surrounding formation from collapsing the wellbore. Additionally, the density of drilling mud must also be great enough to prevent an undesirable ingress of fluid that may be present in the surrounding formation from entering the wellbore, which can tend to migrate to the surface and increase the potential for a well blowout scenario. Accordingly, the drilling mud is generally designed and formulated, and in particular the density or “weight” of the mud is often adjusted, in view of these various operating scenarios with a goal of providing a more reliable, consistent, and predictable overall drilling operation.
Drilling muds commonly include many different types of desirable solid particles that aid in performing one or more of the functions and purposes outlined above. These solids particles used in drilling muds may have one or more particular properties which makes their presence in a particular drilling mud mixture desirable and beneficial. For example, in certain applications, some solids particles may need to be of a certain size or size range, which may be useful in sealing off more highly permeable formations so as to prevent the loss of valuable drilling fluid into the formation—so-called “lost circulation materials.” In other applications, such as when relatively high wellbore pressures are anticipated or encountered, other solids particles may need to be of a certain density or “weight” so as to control and balance forces within the wellbore, which may be added to the drilling mud as necessary so as to guard against wellbore collapse or even a well blowout during the drilling operation.
In some drilling applications, the base fluid of the drilling mud—which may substantially be water, a hydrocarbon-based fluid, a synthetic hydrocarbon replacement fluid, and/or some combination thereof—may be used to create what is sometimes referred to as an “unweighted” drilling mud. Typically, the base fluid is the primary constituent in an unweighted drilling mud, and any suspended solids particles present in the unweighted drilling mud would usually only include so-called “native solids,” which are generally any dispersed clays, sand, chert, and/or other rock that originates from formations being drilled. In general, unweighted drilling muds are most often used in relatively shallow drilling operations when the wellbore formation pressures are typically lower than the competing hydrostatic head pressure of the drilling fluid. However, in drilling applications where the formation pressures are high enough to exceed the hydrostatic head pressure of the drilling fluid, solids particles having a greater density, or specific gravity, must be added to the drilling mud mixture so as to increase the overall density of the mud, thus creating what is often referred to as a “weighted” drilling mud.
For example, in some applications, high density particulate materials such as barium sulfate, or barite, (BaSO4), are often used for this purpose, as their greater unit volumetric weight serves to counterbalance the high formation pressures and/or the mechanical forces that are often caused by formations that would otherwise begin sloughing during the drilling process. Furthermore, in at least some cases, solids particles may be added to the drilling mud based on a combination of the particle size and density, such as when a specific combination of the two properties may be desirable. As would be appreciated by those of ordinary skill, the drilling mud in general, and the added solid particles in particular, can often be very expensive. As such, in some applications, various systems and processes have been implemented so that the desirable—and valuable—solids particles can be recovered and re-used during the ongoing drilling cycle.
Once the drilling mud has served its initial purposes downhole, the mud is then circulated back up and out of the well so that it can carry the drill cuttings that are removed from the advancing wellbore during the drilling operation up to the surface. As may be appreciated, the drill cuttings that are generated during the drilling operation, which are also solids particles, are generally thoroughly mixed together with other beneficial solids particles that may have been added to the base fluid so as to make up the drilling mud. Therefore, these drill cuttings must be separated from the desirable solids particles which, in the case of weighted drilling muds would be higher density solids particles, such as barite and the like. In the best possible drilling scenario, it is advantageous for the drill cuttings to be substantially larger than the desirable solids particles making up the drilling mud, thus enabling a substantial portion of the drill cuttings to be removed during a primary separation step using vibratory separator devices that separate particles based upon size, such as shale shakers and the like. However, in most applications, a portion of the drill cuttings returning with the drilling mud are similar in size, or even smaller than, at least some of the desirable solids particles contained in the drilling mud, in which case secondary separation devices, such as hydrocyclones and/or decanter centrifuges and the like, are often employed so as to obtain further particle separation.
For example, in accordance with API Specification 13A, barite that is added to drilling mud is required to be made up of particles having a particle size distribution wherein no more than 3 weight percent is coarser than 75 microns and no more than 30 weight percent is finer than 6 microns. As such, the majority of the barite particles that are used in drilling mud have a particle size that ranges from 6-75 microns, with the allowances outside of this range as noted above. Furthermore, the median particle size in this distribution range is typically on the order of around 50 microns. When using a shale shaker or other vibratory separator, better operational proficiency is achieved by the machines when the size of the drill cuttings particles are at least twice that of the valuable solids particles—e.g., barite—that are desirable to keep in the drilling mud mixture. Therefore, drill cuttings particles that are 150 microns or larger can generally be separated rather efficiently from particles such as barite using well known and commonly available screen separation technology.
However, it should be appreciated that while the sizes of a large majority of the drill cuttings particles enable them to be separated with machines that utilize vibratory screening techniques, such as shale shakers and the like, the sizes of many solids particles do not always conveniently fall within the size range that permits such relatively easy separation, e.g., the 150 micron size threshold noted above. The simple reason for this is that there are many factors that can influence the eventual size of drill cuttings particles returned with the drilling mud, such as: formation lithology (different rocks/minerals that are encountered as the wellbore progresses through different formation strata); type of drill bit used (PDC bits cut or shear rock; roller-cone bits crush rock); weight on bit (downward force exerted on the bit by gravity and/or mechanical forces); drilling rate (feet per hour), and the like. Accordingly, the sizes of at least some of the drill cuttings particles will fall squarely within the size range of the drilling mud's desirable solids particles, such as the 6-75 micron size range of barite particles, as noted above.
There are a variety of reasons why it is desirable, and even necessary, to remove as many of the drill cuttings particles from the drilling mud mixture as possible. A first reason would be so as to control and/or maintain the drilling mud chemistry and composition within a desirable range as consistently as possible. For example, the presence of drill cuttings particles in the drilling mud mixture may have a significant effect on the weight of the mud, which could potentially lead to wellbore collapse, and/or a blowout scenario associated with possibly hazardous overpressure conditions within the well. More specifically, because the specific gravity of the drill cuttings particles (that is, the ratio of the drill cuttings particle density to that of water) are normally significantly lower than that of the desired solids particles in the drilling mud, e.g., barite, then the presence of cuttings particles left in the mud by the typical solids removal processes can cause the weight of the drilling mud to be lower than required when the cuttings particles displace the barite. Mineralogically pure barite, or barium sulfate, has a density of about 4.5 gm/cm3 (or a specific gravity of 4.5), whereas the types of cuttings materials that are most typically encountered during drilling operations have a specific gravity that is less than 3.2, and generally falls in the range of about 2.5 to 3.0.
Additionally, the presence of undesirable solids materials in the drilling mud can also have an adverse effect on the flow and/or hydraulic characteristics of the mud, which could thus potentially have a detrimental influence the operational efficiency of the hydraulically driven downhole tools, lubrication and cooling of the drill bit, and the like. Furthermore, depending on the types of materials (e.g., rocks/minerals) that make up the drill cuttings, the drill cuttings particles can be highly abrasive, and therefore could be damaging to the drilling mud circulation equipment, such as mud pumps, seals, valves, and the like. In such cases, expensive drilling downtime may be encountered during the repair and/or replacement of inordinately worn or damaged equipment. Accordingly, rig operators generally go to great lengths to remove as many of the returned drilling cuttings particles from the drilling mud as is possible. Furthermore, in the case of weighted drilling muds, operators also make every reasonable effort to recover and re-use as much of the high density (e.g., barite) particulate material as may be economically feasible. To that end, various systems and methods have been employed in an effort to separate high density solids particles from low density drill cuttings particles.
Barite recovery in many prior art applications is generally performed after at least a primary separation step based on particle size has been performed, for example, by using vibratory separator screening systems such as shale shakers. Typically, the prior art method of recovering and re-using the beneficial high density particles (e.g., barite) that have been added to weighted drilling mud involves a three-step approach, which includes: 1) removing barite from the spent (returned) drilling fluid; 2) removing the detrimental low-density solids (small-sized drill cuttings particles) from the drilling fluid; and 3) returning the cleaned drilling mud and recovered barite to the drilling rig's active mud system for re-use. Typically, the solid particle removal steps noted above are performed using decanter centrifuges, which apply centrifugal forces to the drilling fluid so as to separate heavier/more dense solid particles from lighter/less dense fluids. The operation of decanter centrifuges is well known to those having ordinary skill in the art and therefore will not be described in detail herein other than as may be necessary to convey the operating principles of exemplary prior art barite recovery systems.
When a weighted drilling mud is used during drilling operations, both the beneficial high density (e.g., barite) particles and detrimental low density (drill cuttings) particles will be present in the spent drilling mud after it has been returned from a drilled wellbore. When a decanter centrifuge receives the spent drilling mud containing both high and low density particles and is operated to separate the drill cuttings (low density) solids particles from the mud, the barite particles will also be removed during the same operation, since the centrifugal forces imposed on the low density particles will also cause the higher density particles to separate from the fluid. In order to avoid simultaneously separating the high and low density particles from the spent drilling mud during the same solids separation step, typical barite recovery systems utilize two decanter centrifuges that are arranged in a series operation so as to first remove the higher density barite particles from the drilling mud in a first centrifuge, after which the lower density drilling cuttings particles are moved from the mud in a second centrifuge.
Due to their higher relative density, or specific gravity, barite particles will more readily drop out of the drilling mud than will the lower density drill cuttings particles when subjected to the same level of centrifugal force. As such, a lower centrifugal force is required to remove the high density barite particles than is required to remove the low density drill cuttings particles, which is used to advantage in the typical prior art barite recovery systems. In such systems, the first decanter centrifuge is operated at a substantially lower rotational velocity (RPM) than the second centrifuge, and thus a lower centrifugal force is created within the first centrifuge than within the second centrifuge. Accordingly, the lower centrifugal force created within the first decanter centrifuge will be sufficient to remove the higher density barite particles, but will be less effective in removing the lower density drill cuttings particles. The fluid effluent, or overflow, exiting the first centrifuge is therefore laden with minimal amounts of the higher density barite particles and relatively high levels of lower specific gravity solids, such as drill cuttings particles. The overflow fluid is then directed to the second decanter centrifuge for further separation processing. As noted previously, the second decanter centrifuge is operated at a substantially higher rotational speed (RPM) than the first decanter centrifuge, which in turn applies a substantially greater centrifugal force on the overflow fluid received from the first centrifuge. In this way, the removal of lower density drill cuttings particles from the drilling mud can be maximized, after which the cleaned mud is returned to the drilling rig's active mud system.
FIGS. 1A-1C are schematic flow diagrams that illustrate a prior art drilling mud treatment system 100 that includes a solids removal and recovery system 170 that can be configured to treat both weighted and unweighted drilling fluids. In particular, the solids removal and recovery system 170 shown in FIG. 1A is in an operational configuration that allows desirable high specific gravity particles, e.g., barite, to be recovered from a drilling mud 110 and returned the recovered barite to the active mud system for re-use in further drilling operations. In some instances, the solids removal and recovery system 170 may be referred to herein as a barite recovery system 170 for simplicity.
As shown in FIG. 1A, drilling mud 110 that is returned from a drilled wellbore (not shown) flows through a spent mud flow line 102 to a primary solids separation apparatus 104, such as a shale shaker and the like, for an initial separation step. As the drilling mud 110 passes through the shale shaker 104, larger drilling cuttings 107 are separated from the mud 110 and directed to a drilling cuttings tank or pit 108. The portions of the drilling mud 110 passing through the various screening decks of the shale shaker 104 flow down to a sump 106, and from there are directed to the active mud system tank or pit 112 for further processing.
In some configurations of the drilling mud treatment system 100, a flow of the drilling mud 110 may be directed through one or more intermediate mud treatment and/or solids separation apparatuses, which are collectively depicted schematically in FIG. 1A as system 160. For example, the system 160 can include an apparatus for removing entrained gases from the drilling mud 110 (e.g., vacuum or atmospheric degasser), as well as apparatus(es) for removing sand and/or silt from the mud 110 (e.g., desander and/or desilter hydrocyclones). It should be appreciated that the design and operation of such additional treatment and/or separation apparatuses is well known in the art, and as such will not be described further.
As noted previously, the barite recovery system 170 schematically depicted in FIG. 1A is configured for recovering barite from the drilling mud 110 for re-use in further drilling operations. As shown in FIG. 1A, the barite recovery system 170 includes first and second decanter centrifuges 124 and 144, both of which are operated to remove solids particles from drilling mud 110. The barite recovery system 170 also includes a barite mixing tank 134 that is used to temporarily store and blend barite that has been recovered from the drilling mud 110 during the barite recovery process, as well as first and second solids disposal pits or tanks 132 and 150 that can be used for temporary storage of the solids that are removed from the mud 110 using the respective first and second centrifuges 124, 144, prior to eventual disposal. Furthermore, the barite recovery system 170 includes a plurality of pumps 120, 138, 140, and 145 are used to generate various flows of drilling mud 110 through the system 170, as well as a plurality of flow redirection devices 130, 135, and 142 that can be used to direct the various flows of drilling mud 110 to specific apparatuses of the system 170, as will be further described below.
As shown in FIG. 1A, during a barite recovery operation, a first pump 120 is used to generate a flow 113 of drilling mud 110 from the mud tank 112 to an inlet of the first decanter centrifuge 124. The first decanter centrifuge 124 receives the entire flow 113 of drilling mud 110 and is operated at a relatively low RPM (as described above) so as to separate the flow 113 into a first solids underflow, or reject, portion 126 and a first fluid overflow portion 128. The first solids underflow portion 126 is primarily composed of a relatively high percentage of higher density barite particles and a relatively small percentage of lower density drill cuttings particles mixed into a slurry with a small amount of drilling fluid, whereas the first fluid overflow portion 128 is primarily made up of drilling fluid 110 with a relatively high percentage of lower density drill cuttings particles and a relatively low percentage of higher density barite particles.
Upon exiting the underflow outlet of the first decanter centrifuge 124, the first solids underflow slurry 126, which is primarily composed of recovered barite, flows to a first flow redirection apparatus 130, which is operated so as to direct the barite underflow slurry 126 to the barite mixing tank 134, as is indicated by the blackened flow branch of the first flow redirection apparatus 130 and the dashed line between the first apparatus 130 and the solids disposal tank 132. Typically, the first flow redirection apparatus 130 is a simple slide or chute that can be configured and arranged so that the first solids underflow slurry 126 is directed to the appropriate location or apparatus, such as the barite mixing tank 134 as shown in FIG. 1A, or to a solids disposal tank 132, as will be further described in conjunction with FIG. 1B below. Additionally, when the prior art system 170 is configured for barite recovery, a flow 115 of drilling mud 110 is typically generated by a second pump 138 from the mud tank 112 to the barite mixing tank 134, where it can be mixed and blended with the barite underflow slurry 126 by an agitator 136, thereby creating a blended drilling mud/barite mixture 139 that can be pumped back to the mud tank 112. In the barite recovery configuration depicted in FIG. 1A, the second pump 138 generates the flow 115 of drilling mud 110 to a second flow redirection apparatus 135, such as a three-way valve, which is in turn operated so as to direct the flow 115 to the barite mixing tank 134, as indicated by the blackened flow branch of the second flow redirection apparatus 135. Thereafter, a flow 137 of the blended drilling mud/recovered barite mixture 139 is then generated back to the mud tank 112 by a third pump 140 so that the recovered barite can be re-used for further drilling operations.
Also as shown in FIG. 1A, when the barite recovery system 170 is configured in the barite recovery mode, the first fluid overflow portion 128 exiting the overflow outlet of the first decanter centrifuge 124 flows to a third flow redirection apparatus 142, e.g., a three-way valve or flow chute, which is operated or configured so that the first overflow portion 128 is directed to an overflow staging tank 143, as indicated by the blackened flow branch of the third flow redirection apparatus 142. A fourth pump 145 is then used to pump the first overflow portion 128 from the overflow staging tank 143 to a second decanter centrifuge 144 for further solids particle separation. The second decanter centrifuge 144 receives the first fluid overflow portion 128 and is operated at a substantially higher RPM relative to that of the first centrifuge 124 (as described above) so as to separate the first overflow portion 128 into a second solids underflow, or reject, portion 146 and second fluid overflow portion 148. The second solids underflow portion 146 exiting the second centrifuge 144 typically flows into a solids disposal tank or pit 150, and is composed primarily of lower density drill cuttings particles mixed into a slurry with some amount of drilling fluid, as well as a relatively small amount of higher density barite particles that are carried over from the first centrifuge 124. The second fluid overflow portion 148 exits the second decanter centrifuge 144 as a “clean” drilling mud 110, which generally contains only relatively small amounts of either high or low density solids particles, and is returned to the mud tank 112 for mixing and blending with the recovered barite, as shown in FIG. 1A.
In some prior art applications, the second fluid overflow portion 148, i.e., the “cleaned” drilling mud 110, is returned to the suction chamber or compartment (not shown) of the mud tank 112, along with the flow 139 of blended drilling mud/recovered barite mixture. A mud pump 116 then draws the cleaned and treated drilling mud 110 through a suction line 114 from the suction chamber and pumps the treated drilling mud 110 through a discharge line 118 to a rotary line (not shown) attached to a drill string (not shown), and back down into the wellbore (not shown).
FIGS. 1B and 1C schematically depict the drilling mud treatment system 100 of FIG. 1A wherein the barite recovery system 170 is configured to process unweighted drilling mud 110. As noted previously, an unweighted drilling mud is one wherein most if not all of the solids particles remaining in the flow 113 of drilling mud 110 treated by the system represent drill cuttings particles, because no high density barite particles have been added to, or need to be recovered from, the drilling mud 110. Turning first to FIG. 1B, the barite recovery system 170 is configured so that the first and second decanter centrifuges 124 and 144 are arranged for parallel flow. More specifically, since there is no barite being recovered by the first decanter centrifuge 124, then there is no underflow slurry 126 of recovered barite being sent to the barite mixing tank 134 for the flow 115 of drilling mud 110 to be mixed with. Accordingly, the second flow redirection apparatus 135 is operated so that the flow 115 of drilling mud 110 from the mud tank 112 that is generated by the second pump 138 is directed to the second centrifuge 144 for separation, thus bypassing the barite mixing tank 134, as is indicated by the blackened flow branch of the second flow redirection apparatus 135 and the dashed line between the second apparatus 135 and the barite mixing tank 134. Meanwhile, the flow 113 of drilling mud 110 generated by the first pump 120 is still directed to the first centrifuge 124 for separation. Typically, the two centrifuges 124, 144 are operated in substantially similar fashion, e.g., at similar RPM's, so as to separate as much of the solids particles, e.g., drill cuttings, as possible from the drilling mud 110, irrespective of particle size and/or particle specific gravity.
In most applications, the first solids underflow 126 exiting the first decanter centrifuge 124 is a slurry containing a high percentage of the solids particles that initially entered the first centrifuge 124 with the flow 113, mixed together with a small amount of drilling mud 110. The first underflow slurry 126 then flows to the first flow redirection apparatus 130, which is operated and/or configured so as to direct the first underflow slurry 126 to a solids disposal tank 132. In this way, the barite mixing tank 134 is essentially bypassed, as indicated by the blackened flow branch of the first flow redirection apparatus 130 and the dashed line between the apparatus 130 and the barite mixing tank 134. Similarly, the second solids underflow 146 exiting the second decanter centrifuge 144 is also a slurry containing a high percentage of the solids particles that initially entered the second centrifuge 144 with the flow 115, mixed together with a small amount of drilling mud 110. As previously noted with respect to FIG. 1A, the second underflow slurry 146 again flows to the solids disposal tank 150.
The first and second fluid overflow portions 128, 148 typically exit the respective first and second decanter centrifuges 124, 144 as substantially “clean” drilling mud 110, that is, the overflow portions 128 and 148 generally contain only relatively small amounts of solids particles. In the system configuration depicted in FIG. 1B, the third flow redirection apparatus 142 is operated and/or configured so that the first fluid overflow portion 128 exiting the first centrifuge 124 bypasses the overflow staging tank 143 and the second centrifuge 144, as indicated by the blackened flow branch of the apparatus 142 and the dashed line between the apparatus 142 and the overflow staging tank 143. The two fluid overflow portions 128, 148 then flow together as a substantially “clean” flow 152 of drilling mud, which is directed back to the mud tank 112 for recirculation into the drilled wellbore (not shown) by the mud pump 116, as previously described.
Since the barite mixing tank 134 is bypassed, and barite is not being recovered from the drilling mud 110 in the system configuration depicted in FIG. 1B, drilling mud 110 is not circulated from the mud tank 112 to the barite mixing tank 134. Furthermore, the agitator 136 is also not operated, since there is no recovered barite or drilling mud 110 in the barite mixing tank 134 to mix and blend, nor is the third pump 140 operated, since there is no drilling mud mixture to be pumped from the barite mixing tank 134 back to the mud tank 112.
FIG. 1C schematically illustrates the drilling mud treatment system 100 wherein the barite recovery system 170 is configured differently from that shown in FIG. 1B for treating unweighted drilling mud 110. In particular, FIG. 1C depicts the barite recovery system 170 wherein the second flow redirection apparatus 135 is again operated so as to direct the flow 115 of drilling mud 110 generated by the second pump 138 to the second decanter centrifuge 144. Additionally, the first pump 120 is shut in, and therefore is not operated to direct a flow of drilling mud 110 to the first decanter centrifuge 128, as indicated by the dashed lines between the mud tank 112 and the first pump 120 and between the pump 120 and the first centrifuge 124. Furthermore, the third flow redirection apparatus 142 is also operated so as to prevent any backflow of drilling mud 110 from entering the underflow outlet of the bypassed first centrifuge 124, as indicated by the blackened flow branches of the apparatus 142 and the dashed lines between the apparatus 142 and the overflow outlet of the second centrifuge 144.
In the operational configuration of the barite recovery system 170 shown in FIG. 1C, the second decanter centrifuge 144 receives the flow 115 of drilling mud 110 and is operated so as to separate the flow 115 into a solids underflow portion 146, which is discarded into the solids disposal tank 150, and a substantially “clean” drilling fluid overflow portion 148, which is directed back to the mud tank 112 for subsequent re-use in further drilling operations. The system configuration depicted in FIG. 1C is used when the volumetric flow requirements for the drilling mud quantities necessary to support drilling operations are substantially reduced when compared to what can be treated in the parallel system flow configuration of FIG. 1B, or when the first decanter centrifuge 124 is taken out of service for maintenance and/or repair.
As noted previously, the barite recovery system generally described above has been used in many prior art applications to separate, recover, and re-use the desirable and beneficial barite particles from spent drilling mud. However, there are significant capital and operation costs, as well as safety and environment considerations, associated with the fabrication, assembly, and operation of such a prior art barite recovery system. For example, a dedicated barite recovery tank is typically required for temporarily storing the recovered barite, which includes a mud agitator for mixing and blending the recovered barite with drilling mud. Furthermore, additional mud circulation pumps are required so as to pump a substantially continuous supply of drilling mud to the barite recovery tank for mixing with the recovered barite, as well as to pump the recovered barite/drilling mud mixture back to the active mud tank. This requires that additional quantities of drilling mud be purchased and kept on hand to support the mud circulation and mixing/blending activities. Additionally, a significant amount of additional piping is required so as to make up the appropriate interconnections between the extra pieces of equipment (tanks, pumps, etc.), all of which can take up a substantial footprint in areas where plot space often comes at a premium. Moreover, operating the additional tankage, pumping, and plumbing equipment can lead to drilling mud spillage, which brings with it the environmental issues associated with any related cleanup activities, including the disposal of the additional volumes of drilling mud that are required to support the overall barite recover operation.
The present disclosure is directed to barite recovery systems and methods of operating the same that may be used to mitigate, or possibly even eliminate, at least some of the problems associated with the prior art systems described above.